Ladies and gentlemen, welcome to Statoil's First Quarter Earnings Presentation, both to the audience here in Oslo and our audio and webcast audience. My name is Morten Johannessen, Vice President, Investor Relations at Statoil, standing in for Hilde Nafstad today.

Before we start, let me say there are no fire drills planned for today. However, should the evacuation alarm go off, you will need to exit through the 4 doors to the left of the building, or this room. The security guards will escort you out of the building.

This morning, at 7:30 Central European Time, Statoil announced its first quarter results for 2013. The press release and presentations for today's event were distributed through the wires and through Oslo Stock Exchange. The quarterly report and the presentation can, as usual, be downloaded from our website, statoil.com. I would ask you kindly make special note of the information regarding forward-looking statements, which can be found at the last page.

Today's program will start with Statoil's CFO, Torgrim Reitan, going through the earnings and the outlook for the company. As usual, the presentation will be followed by a Q&A session. [Operator Instructions]

It is now my privilege to introduce Statoil's Chief Financial Officer, Torgrim Reitan.

Torgrim Reitan

Thank you very much, Morten, and good afternoon, everyone, and good morning to all of you in the U.S.

After 2 years with record results, the earnings this quarter is lower than last year. In the first quarter, we delivered earnings of NOK 42 billion and we produced 2 million barrels per day. Our industrial progress is strong, our guiding remains firm and we are on track for our long-term ambitions.

Our financial results were impacted by reduced prices and lower production. We had earlier said that 2013 production will be lower than 2012, and this is due to commercial decisions we have made to increase value, like NCS divestments. We produced broadly in line with what we needed for the full year. We produced record volumes from our international portfolio, and I'm pleased that we continue our profitable growth outside Norway.

But we had the disruptions at some of our largest fields, reducing production by some 50,000 barrels per day in the quarter. And this led also to a change in the production mix impacting the earnings further. First, realized prices are impacted by a higher share of U.S. gas and more NGL. Secondly, the fields with disruptions have a very low DD&A per barrel; while the recently started ones, naturally, have a very high DD&A per barrel, leading to a higher-than-usual DD&A. Third, operating costs are not variable in the short term and are not reduced when we have production disruptions.

Our results are also impacted by quarter-specific items, which I will refer to. When it comes to cash flow from operation, that is down by NOK 13 billion. That is 19%, and this is a result of reduced production and lower prices.

Our projects are progressing well. We have selected the concept for Johan Castberg in the Barents Sea, formerly known as Skrugard, and also on for Bressay, offshore U.K. We have posted the final investment decision to further extend production at Åsgard in the Norwegian Sea and at Hibernia, offshore Canada. And we have further progress on Aasta Hansteen in Norway and Mariner in the U.K.

I'm very glad to see that we delivered the first wave of those fast-track projects. As you know, we standardize the development solutions for smaller fields, faster and cheaper. Last year, we put Visund South onstream as the first one. And this quarter, we started 4 more: Hyme, Vigdis Northeast, Skuld and Stjerne. All of these were discovered between 2008 and 2010. They have an average breakeven of around $40 per barrel, and there is more to come, so we are on track with fast track.

We will make the concept selection for the giant Johan Sverdrup in the fourth quarter, and we will then return with more details together with an updated resource estimate.

And finally, our exploration team had another great quarter. We made the fourth high-impact discovery in Tanzania in just one year, bringing further robustness to a potential LNG project there. And then we secured 15 interesting leases in the central Gulf of Mexico. 12 wells were completed in the quarter with a 58% success rate. And last but not least, we made a significant discovery at Gullfaks in the North Sea, 40 million to 150 million barrels, high-value barrels, and there's a further upside potential.

In 2011, we announced our strategy for growth up to 2020. We have delivered the first wave of projects, a 3% average growth from 2010 to 2012 and an 8% production growth last year. The first wave of projects are delivered without cost overruns or delays. As you know, we expect a 2 to 3 percentage point average growth in the period from 2012 to 2016. But we have divested assets on the NCS and we have produced a lot for more value over volume strategy last year. So we have said that 2013 production will be lower than 2012, and this will, of course, also impact the earnings.

This quarter, as such, results are down. In addition to reduced production and lower prices, we had production disruptions at In Amenas, Snøhvit, Peregrino and Troll. We have taken forceful actions to bring them quickly back up. Snøhvit started at the 28th of April and is now at close to maximum capacity. Peregrino is ramping up and yesterday, it produced 75,000 barrels per day and it continues to ramp up. And we expect Troll to be back by end of the second quarter. At In Amenas, 2 out of 3 trains have started. Timing and startup of the third train is still uncertain.

We also saw changes in the production mix leading to a lower realized prices. We produced more U.S. gas this quarter. However, realized prices in Europe are on par with last quarter. The share of NGL increased to around 21% on NCS, and as you know, NGL trades currently at a $40 per barrel discount to Brent.

As every quarter, we make adjustments to results. On the NCS, we have adjusted for a one-off effect related to gas lifting. We had lower fair values of derivatives impacted -- impacting our net operating income. And finally, we have adjusted for about NOK 5 billion related to provisions on the Cove Point LNG regas terminal in the U.S.

In the current market, we expect not to use our capacity at that terminal. We have renegotiated and reduced our obligations, and we are now making a provision for all of our remaining tariff payments.

Finally, the devaluation of the bolivar in Venezuela has impacted the results with some NOK 600 million. This is an after-tax effect with no cash impact for starter. This effect is not adjusted for, but is part of the adjusted earnings.

Importantly, we maintained a firm underlying cost control throughout the period. We are keeping operating expenses at our fields stable, and this is something I watch very closely and I will come back to this in further details later.

Adjusted earnings after tax was NOK 12 billion, with an effective tax rate on adjusted earnings of 71.8%.

Now over to the segments. Our Norwegian business delivered adjusted earnings of NOK 34 billion. Compared to the same quarter last year, earnings were mainly affected by the lower production and lower prices, and I will revert to cost and DD&A specifically.

From our operations outside Norway, the adjusted earnings were NOK 5 billion. Our entitlement production grew by 16% and we now produce around 1/3 of our volumes outside Norway. And this generated an EBITDA of around NOK 12 billion. And if you look at the cash flow per barrel from our international portfolio, it is on par with our Norwegian production.

Marketing, processing and renewables contributed by nearly NOK 3 billion. In total, we sold a similar amount of gas as the first quarter last year. However, gas production on the NCS was reduced, mainly due to repairs at Snøhvit and Troll.

We have also increased our gas production in the U.S., as we are hooking up already drilled wells in Marcellus through the gathering systems and infrastructure. The North American gas market is strengthening as demand has exceeded supply and gas storages -- gas storage levels are now below the 5-year average. We have also sold more third party volumes in the quarter. Overall, these effects decreased our average in moist gas, gas price by 11%.

In the first quarter, we produced 2 million barrels per day. This is down 9% from the same quarter last year. And as we said, we expect lower production in 2013 than in 2012. However, production could have been higher without disruptions. 1.3 million barrels per day is produced from the NCS and 700,000 barrels per day from outside Norway, record international production, and this is profitable growth.

On the NCS. The decrease is mainly due to the reduced share at Kvitebjørn, the compressor issues at Troll and the prolonged shutdown at Snøhvit. And as you know, we have restarted Snøhvit production this week. We are also progressing well in replacing the compressor on Troll, and we expect to have most of the capacity back by end of the second quarter. Current reduced capacity at Troll, of course, reduces our flexibility somewhat. Production was positive impacted by our fast-track projects, the ramp-up on Skarv and we have also started production from the newly discovered volumes on Gullfaks.

In the International portfolio, we increased equity production by 6%, that is primarily gas. We are ramping up PSVM in Angola and we are continuing to ramp up in the U.S. onshore. Following the terror attack on In Amenas, our production is significantly reduced there, impacting our overall liquids production.

Then cash flow. Our cash flow from underlying operations was NOK 58 billion in the quarter. This is 19% lower than during the same period last year. The reduction is fully explained by reduced production and lower prices. We invested NOK 427 billion. This is in line with our estimate of $19 billion for the year as a whole. Adjusted net debt-to-capital employed increased from 12.4% from year end to 13.3% at the end of this quarter. So we continue to maintain a firm financial framework and a solid balance sheet. Next quarter, we will pay 2 tax installments. And dividend will be paid in late May, NOK 6.75 per share, and that is representing a direct yield of close to 5%.

Now let us take a look at our costs, starting with the operating expenses. A large part of the costs at our fields are fixed in the short term, and they will not vary directly with -- directly in line with changes in quarterly production. And this means that production disruptions will not lead to reduced OpEx. We are working constantly to improve our cost position further.

In Norway, we have kept the underlying total cost stable for 5 quarters now, and that is despite having more fields into production and despite industry cost inflation. Within marketing, processing and renewables, the improvement program we have put in place is paying off. Quarterly variations will naturally occur due to seasonal changes in volumes.

In the International segment, we are growing, and the growth in operational cost and the SG&A is explained by higher royalties and higher transportation costs.

If we then move to depreciation. We see a stable development in DPN. And as you know, lower production usually means lower depreciation. However, this is offset in the quarter by new fields coming on stream. Fields typically have a higher depreciation at the start of their life cycle. This quarter, we have increased production at Skarv, which is contributing with high depreciation, close to NOK 300 per barrel in DD&A from that field. This will, of course, decrease over time on that field.

We have also had a lower production from older fields like Troll and Kvitebjørn, and they have a depreciation of NOK 20 to NOK 30 per barrel, so it's a very, very big difference. So as you can see, the DD&A in the quarter is impacted by the production mix.

Internationally, you will notice that we have improved as the unit DD&A from the same period last year. So we will continue to improve the cost base. We are simplifying our processes, and we are increasing efficiencies across the company.

In April, we implemented the new staff organization across Statoil and we reduced staffing by 809 man-years. We also continued standardization and industrialization, as demonstrated by the successful fast-track initiative. And we continue to expand our portfolio of suppliers using the global market, further strengthening the competitiveness of our projects.

Now let's take a look at the growth outlook. As we have discussed earlier, our growth will not be linear. The production -- the lower production in 2013 is due to commercial decisions we have made, divesting NCS assets and realizing significant gains. The Wintershall deal will impact production by some 40,000 barrels per day from closing.

We have reduced the rigs on Marcellus, reacting to the price environment, and we have produced NCS gas at a high level in 2012 due to a strong market, and this leaves less capacity for 2013. So this will impact the gas production this year by some 15,000 barrels per day.

The situation at In Amenas in Algerie will also affect output in 2013. In 2012, In Amenas produced 23,000 barrels per day for us.

Second, we expect a growth of approximately 2% to 3% per year on average from 2012 to 2016. And third, in the more long term, we see the growth accelerating from 2016, growing by some 3 to 4 percentage points on average per year as some of our big new developments start to come on stream. So all in all, we are on track for ambition, producing more than 2.5 million barrels in 2020.

Looking at 2013. Snøhvit, Peregrino and Troll will also affect our production in the second quarter. They are now back up, while Troll will be back towards the end of second quarter. For the next quarters, please also take into account the higher share of U.S. gas and the current NGL share in our liquid production.

Finally, planned maintenance is expected to have a negative impact on the quarterly production, around 40,000 barrels per day in the second quarter, most of this is planned outside the NCS. In the third quarter, maintenance is expected to reduce production by around 100,000 barrels per day, the majority on the NCS and more than 1/2 is gas.

For the full year of 2013, our maintenance program is estimated to reduce equity production by around 45,000 barrels per day, and most of this is at our liquid production fields.

We will invest around $19 billion this year, bringing new projects on with a low breakeven price across the portfolio and with industry-leading rates of return. We expect to receive the proceeds from the Wintershall deal during the year. Leading to that net investment, we'll be less than $19 billion, $19 billion is a gross investment number.

We will explore for around $3.5 billion this year and plan to finish around 50 wells. And we will drill approximately 20 high-impact wells from 2013 to 2015.

I know you like to watch our wells, so let me give you some wells to watch in the shorter term. We now kick off 3 exciting drilling campaigns. The Barents Sea with Nunatak in the Johan Castberg area, and that is building in these days; Cachalote in Mozambique was spudded a week ago; and finally, in East Canada, we'd hope to invest [ph], also recently spudded. So it is exciting times for our exploration team and for all of us.

So to round up, our financial results are impacted by disruptions and quarter-specific items, but we are progressing according to plan. We set a new record for international production. We continued our robust project execution and we delivered good on exploration. Looking ahead, we are well positioned to grow and create value. We continue to efficiently execute our projects. We maintain a firm financial framework. We continue to pay a predictable and growing dividend. And as you know, the board has proposed to pay NOK 6.75, and we will do all of this by keeping a very solid balance sheet.

So thank you very much for your attention, and then I'll leave the work to you, Morten, to lead us through the Q&A session, so thank you.

Morten Sven Johannessen

Thank you very much, Torgrim. We will now turn to the Q&A session.

Question-and-Answer Session

Morten Sven Johannessen

Torgrim will be joined by Senior Vice President for Accounting and Financial Compliance, Ørjan Kvelvane; and Senior Vice President for Performance Management and Risk, Svein Skeie. We will take questions from the audience and over the telephone. I will first ask the operator to explain the procedure for asking questions over the telephone. Please, operator.

Operator

[Operator Instructions]

Morten Sven Johannessen

[Operator Instructions] We will start with questions from the audience here in Oslo. [Operator Instructions] First question from Oslo, Anne.

Anne Gjøen - Handelsbanken Capital Markets, Research Division

Anne Gjøen, Handelsbanken Capital Markets. I have a question in relation to natural gas or natural gas prices. Because you've given before this result release and the internal gas price, it's a margin now of NOK 0.10. I know that it's changed principles when it comes to this pricing, but is it possible to give some indication? Is this low margin any indication of what we could expect going forward, or is this just kind of very weak in this single quarter?

Torgrim Reitan

Okay. Thank you, Anne. So let me start, and Svein, you can add on, if you like. The way that the internal price is working between natural gas and the Norwegian area is on a day-ahead basis, I mean, the average of day-ahead prices for what is gas index. While natural gas, they have a lot of volume to deal within the markets, so they typically sell quite a bit in the front months. So in a quarter where you have had rising prices on a day-ahead basis, the internal price becomes higher than actually what natural gas has realized in the way they have sold the gas. So I think that is the main explanation for the deviation this quarter and that explains that -- the rather small margin on the natural gas side. Svein, something to add?

Svein Skeie

Well, I think you had covered it well. It's also about the cost element that goes into it and the -- and all that is being recovered, so -- but it's based on other [ph] prices on the long term and then they go into LNG price assessment and the spot prices and then a cost element.

Torgrim Reitan

So what you could expect is that when prices moves in other direction, you will see the opposite effect. And then the natural gas business is, no matter what, measured on how much value they can add on top of what they pay for gas.

Morten Sven Johannessen

Next question please from Oslo.

André Baustad Benonisen - Danske Bank Markets, Research Division

André Benonisen from Danske Bank. What is a realistic EBIT level from marketing division going forward?

Torgrim Reitan

Okay. Thank you, Andre. I think it's fair to say that we should expect fluctuations from quarter-to-quarter. Last year was a very strong quarter, strong year in most quarter from that business. If you divide it into the sub-elements, the processing facilities, the refineries, I mean, they are very much a function of the refinery margins, which is healthy this quarter. Cost had been taken significantly down. On the trading side, you should also expect that it's -- for an oil company, it is easier to make money in market with Contango than in backwardation due to that long oil and long gas. So the structure of the market will typically impact the returns. So they are performing generally strong, generally very good contribution to the earnings, but it will fluctuate quarter-by-quarter. So this is a disappointing quarter on the trading side.

André Baustad Benonisen - Danske Bank Markets, Research Division

Another question. Could you give some more flavor on some of the important international fields like Peregrino and Caesar Tonga, also maybe Leismer?

Torgrim Reitan

Okay. Starting with Peregrino, Peregrino have the well capacity for around 100,000 barrels per day in production. We have had a turnaround this quarter that -- and then we started up and then we had some issues on the top side. That is now solved, so it is ramping up. So yesterday, it produced around 75,000 barrels per day. On Leismer, production from Leismer is going very well. The energy efficiency is improving and the production contribution from Leismer in the quarter is around 18,000, 19,000 barrels per day. And then you asked about...

André Baustad Benonisen - Danske Bank Markets, Research Division

Caesar Tonga?

Torgrim Reitan

Caesar Tonga.

Svein Skeie

Caesar Tonga, after the start-up, has performed pretty well and is now producing around 9,000 barrels, just below 10,000 barrels in the first quarter of 2013 in the Gulf of Mexico.

Morten Sven Johannessen

Next question from Oslo, please?

Ole-Jacob Storvik - Fearnley Securities AS, Research Division

Ole Storvik, Fearnley Securities. And can you say something about how we expect them to wrap up from Skarv and the fast-track projects in Norway? And you also have a backlog of drilled wells in the Marcellus that you are completing today?

Torgrim Reitan

Okay. Thank you, Ole-Jacob. On Skarv, BP is the operator there, so they are best to answer on that specifics. But it is producing well, currently, and it is continuing to ramp up. When it comes to the fast-track, we have now 12 fast-track projects in the portfolio on what has been started and what we are working on. In 2014, we expect that portfolio to produce some around 100,000 barrels per day for us, so it's actually more and quicker than we expected than we started with these projects. So all of them have performed well and delivered generally earlier and at lower cost than we had expected. So I think this is a concept that we are very enthusiastic about, and we see the potential for this way of working, and we are looking at stabilization and simplification across other projects as well. When it comes to Marcellus, we have quite a lot of wells in the inventory that wait for infrastructure gathering systems to bring them to the high-pressured interstates. So the inventory there is several hundred wells. And the way we work is that we have reduced the rig count and we drilled 1 well pads that we can return to and drilled 5 more, and that is to keep the acreage. So we take -- we build up a pad and we drill 1 well and hook-ups. So there will be a lot of very attractive wells to drill later in this area. And also, the Marcellus gas, that is now being sold in Toronto. Statoil Marcellus gas is sold in Toronto, generally around $1 higher than -- $1 or $1.05 higher than in the Marcellus area, and that uplift is very welcome in the current price environment.

Morten Sven Johannessen

And now we'll take a question over the telephone. Please, operator.

Operator

We will take our first question from Lydia Rainforth from Barclays.

Lydia Rainforth - Barclays Capital, Research Division

If I could ask 2 questions, please. The first one on the cost base in the Norway side. Now you did say that the underlying costs were flat against industry cost inflation. I'm just wondering where specifically, Statoil is able to make savings within the cost structure. And then, the second one, if I could just have that one in, is on the level of disruptions that you saw in the quarter in Norway. Is there anything that you can do to actually improve their reliability? Or is this just something that we should start to add with some ongoing contingencies going forward?

Torgrim Reitan

Okay, thank you. First, on the costs. I'm very glad to see that all the efforts put in place is working. There's a lot of sources of that. One is the ability to take out synergies across assets and fields. One is related to logistics and optimizing that, and then it's about procurement. We don't have to procure on an asset-by-asset basis what we procure on the portfolio level. That makes us able to have much more flexibility and also to capture opportunities in the market. So -- and then there's a list of -- much longer list on everything that is done in that perspective. So I'm very glad to see that, that is working. And we have worked this pretty hard for a few years. When it comes to the level of disruption, I will not read this quarter as a change in sort of how things work on NCS. Generally, the technical conditions is very good. We use -- when it comes to maintenance, we use a lot of efforts to prevent it on preventive maintenance before things happen, and that has worked very well. When that is said, I'm of course not satisfied with the disruptions we have said -- have seen. Snøhvit has had its challenges since the start up. Peregrino is -- have run an issue more than anything else. And Troll is an electric motor on one compressor, is related to that.

Morten Sven Johannessen

Next question from the telephone, please.

Operator

We'll now take our next question from Haythem Rashed from Morgan Stanley.

Haythem Rashed - Morgan Stanley, Research Division

One clarification, if I may, and also one question. Just firstly, on the production, I know you sort of highlighted where we are on the various different fields that were affected in the quarter, In Amenas, Peregrino and Snøhvit. I just wondered if we could sort of -- if you give a bit of color in terms of how we should think of about the impact to the full year? I know -- presume you're not willing to provide sort of more specific guidance on the guidance you've already provided around production being lower year-on-year. But if we were to sort of take into account some of the impacts we've had in 1Q and their knock-on impact to 2Q, do you feel comfortable to sort of offset that somewhat with some of the other sort of impacts that you have? Such that your initial assessment of production lower year-on-year is effectively the same, or are you talking about incrementally lower with what you had talked about earlier on the year? The second sort of question I had is actually just about Tanzania. I just wondered if you could give us an update there. We see good progress being made around building the resource up there, reaching us here, obviously, providing updates recently. Could you just provide us with an updates on how discussions are going amongst yourselves as the partners in the blocks and whether there are sort of any particular milestones that need to be achieved before we start to see a development so that plans accelerate?

Torgrim Reitan

Thank you very much, Haythem. On the production and the impact for the full year, I mean, if you take -- these are disruptions that sort of we haven't planned for and so on. So, of course, it's sort of impacting without us having taking that into the forecast. When that is said, there's a lot of moving parts in our portfolio as well. Now we have the Gullfaks wells, the new discovery in Gullfaks, that is put into production right away and is producing well. So it is part of there and the totality, but I'm not ready to put forward any specific impact on an annual basis. But our guiding remains firm and things are up and running, more or less, as we speak. When it comes to Tanzania, the resources there is growing. I'm very glad to see that. We are discussing with the partners, and BG especially, as the operator in Block 1. Things are progressing well. We are currently discussing location for the onshore plant. So together, we aim to make that decision together with the Tanzanian authorities by end of this year. So things are progressing well on all fronts in Tanzania.

Morten Sven Johannessen

Can we have another question from the telephone, please?

Operator

Yes. Our next question comes from Nitin Sharma from JPMorgan.

Nitin Sharma - JP Morgan Chase & Co, Research Division

My question is on the provision relating to Cove Point. Could you please clarify how much, if any, book value of Cove Point you're carrying today? And also maybe some details on the underlying assumptions behind the current provision?

Torgrim Reitan

Okay, thank you. So Cove Point. Cove Point was -- is a re-gas terminal in the U.S. where we have capacity. We don't own it. We have never owned it. We have reserved capacity there. So there is no book value in the books related to Cove Point. In the current market environment, we don't see that we will use that terminal for the foreseeable future. We have, therefore, reduced or renegotiated a contract and taken down our future commitments to pay tariffs there. So from a cash flow perspective, that means that there will be less tariff payments in the future on the Cove Point. But at the same time, we have made up our mind and said we don't think we will use the capacity that we have left, so we make provisions on onerous contract. We look at this as an onerous contract and make provisions for some NOK 5 billion, and that is equal to all the remaining tariff commitments in the future. So it's sort of the provision covers for all future commitments.

Nitin Sharma - JP Morgan Chase & Co, Research Division

Just to clarify that point. Was this contract of the nature where even though you may not be using the capacity, you'll still be obliged to make a certain payment over a certain period of time? And what do you think today will continue to make that payment? All we do is write it off today. Would that be the right way of putting it?

Torgrim Reitan

Not sure I fully understood it. But yes, there are still tariff payments to be made. It is take-or-pay obligations, but they are less than it was before the renegotiations, and then we have made provisions for all remaining payments to Cove Point.

Morten Sven Johannessen

We'll have another question from the telephone, please.

Operator

Yes. Our next question comes from Rob West from Sanford Bernstein.

Robert West

My question is on the back end. Just looking at the production back to the middle of 2011, you've ramped up there consistently, but this is the first quarter where we've seen kind of flat-to-down volumes. My question is what's behind that decrease? Is it where you're drilling or is it the amount of drilling you're doing? Is it more of a seasonal factor? And could you give us some guidance on where you expect that production to run over the rest of the year?

Torgrim Reitan

Okay, thank you. Those at back end, we have approximately double the productions since we acquired it a bit more than a year ago. So it is progressing well. We are earning good money in -- from that asset currently. And we have taken down the rig count a bit. So we are now at around 10 rigs, 11 rigs, and we will go to 10 rigs if we find the appropriate level and speeds to run that asset on, because the key at Bakken is to see so that you'll learn across all your drilling teams with everything that you're testing on frac-ing, on well spacing and all of that. So we find sort of that the right speed moving forward. So this is an asset that we will continue to grow. And it's flattish, was flattish from fourth quarter to this quarter? I didn't -- you have said that. Yes, yes, so I think it is still an asset that we will continue to grow.

Morten Sven Johannessen

We'll take another question from Oslo. Any? No. Then we'll have another question on the telephone, please.

I noticed on the international E&P tax rate, it seemed like a little bump sequentially. I'm just wondering if you could explain some of the reasons why it's a little higher this quarter?

Torgrim Reitan

Okay, thank you. So generally, we say that the tax rate on the international business should be expected to be 50% to 55%. On adjusted earnings, it is 66% this quarter. Key explanation to that is the devaluation of the bolivar in Venezuela. That is NOK 600 million reduction in earnings, both pretax and after tax. And so that sort of takes the tax rate and you mentioned the net earnings. So that is the main explanation to that.

Morten Sven Johannessen

Next question on the telephone, please.

Operator

Our next question comes from Mark Bloomfield from Deutsche Bank.

Mark A. Bloomfield - Deutsche Bank AG, Research Division

Yes, another question on tax, please. If I look through the uneven quarterly payment schedule for your tax, for the last 3 years, you've consistently reported cash tax below P&L tax, which I presume reflects your investment levels. I was wondering if you could perhaps quantify what P&L versus cash-tax delta you're assuming in your guidance of $24 billion of average annual operating cash between 2013 and '16?

Torgrim Reitan

Okay, Mark, thank you. First of all, this is very much related to the Norwegian tax system where you have very good, very high tax depreciation from day 1, leading to low payable taxes when you invest. So as you know, be that 130% depreciation towards the high tax rate, you pay only 7% of the investments within -- by 6 years. So that is what you see in the difference between pay taxes and the taxes in the comps. So with that growing investment level, there will be a growth in deferred taxes, and I think that was the question, Mark. And to what extent this will impact towards 2016 is that as long as long as there is a growing investment level in Norway, you will have generally a growth in deferred taxes and paid taxes, it will be less than reported taxes.

Mark A. Bloomfield - Deutsche Bank AG, Research Division

But could I just come back on that, if it's okay. I mean, you guided around cash flow growing or operating cash flow growing quite substantially between 2012 and '16, and presumably part of that reflects the benefit of this differential between P&L and cash tax. So are you able -- I understand the reasons behind it, are you able to quantify the delta?

Torgrim Reitan

No, Mark. I'm not able to quantify it. And that's sort of not the level that I would like to guide on either. But generally, with our growing investment level in Norway, you will have such effects in the cash flow.

Morten Sven Johannessen

Next question on the telephone, please.

Operator

Our next question comes from Teodor Nilsen from Swedbank First Securities.

Teodor Sveen Nilsen - Swedbank First Securities, Research Division

I just want to follow up on the Tanzania questions. You currently have a pretty high owner share in the life business down there. Will you consider any plan down stair? And also, when we should expect first gas from those discoveries?

Torgrim Reitan

Okay, thank you, Teodor. On potential farm, then that's, of course, nothing I could comment on. We have a significant share and we are an operator in -- the operator in our block, which is important to us. So when it comes to first gas, I -- that's too early to say. Things are progressing well. We are going to select a site for the onshore development. And then things are progressing on the regulatory side and also on concepts. But it's fair to say that we really would like to use even more appraisal and even more drilling in this license because there are lot of prospects that we want to look into before we make a decision here. So it's too early to say when this gas will come to market.

Teodor Sveen Nilsen - Swedbank First Securities, Research Division

Okay, but it's not that you do not need any production from Tanzania to reach your 2020 guidance?

Torgrim Reitan

You're absolutely right. We have not taken into account any production from Tanzania in that guiding.

Morten Sven Johannessen

Our next question on the telephone, please.

Operator

Our next question comes from Marc Kofler from Macquarie.

Marc B. Kofler - Macquarie Research

Just 2 things, please. Firstly, in terms of contributions from new projects, I was wondering if you're able to give us a number in terms of what you'd expect for new project startups to contribute to 2013 group production? And then secondly, just going back to the NCS and the profitability, are you able to just give us some sort of indication in terms of how you'd expect unit profitability to be moving on a quarterly basis? I'm particularly thinking second quarter versus the number you posted today.

Torgrim Reitan

Okay, thank you. Svein, maybe you can take the question on the unit of production cost. On the startups going forward, we have a pretty large portfolio of assets that are in the sort of final part of the construction phase. Goliat, Valemon, Gudrun, Svalin, CLOV and Silar [ph] . Big projects of Marulk ,Hibernia and so on. So there's a lot of project lined up. So those are for 2014 and typically towards the end of 2014. And then there are ramp ups in Skarv, it is in PSVM. We're ramping up for unconventional part and a few others as well. But 2013 will be lower than 2012.

Svein Skeie

Yes, on the unit production cost. As Torgrim said it in his presentation, we see a stable underlying cost pressure on the Norwegian continental shelf, even though we are pretty more -- fits into production. Now when we're getting Troll and Snøhvit back into production, that, will of course, offset some of the production cost on that field. However, what we should also take into consideration for the full year is the turnaround effect that we typically have been -- yes, most of it towards the third quarter on the Norwegian continental shelf, so that will also affect the unit operation costs.

Morten Sven Johannessen

Our next question on the telephone, please.

Operator

Our next question comes from Peter Hutton from RBC.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Two questions, but because I can't count, 3 really. First of all, can you just give us some of the insights why you decided to include the NOK 0.6 billion write-off on the Venezuela asset? And within the underlying results, and I guess it's commendable with a lot of people -- a lot of your peers may not have done that, and it does make quite a difference to the overall. So what was the thinking as to -- should that be in or out? The second is you have mentioned and you gave us an update on the wells to watch and when these were spudding, but can you give an indication as to what kind of drill times are expected? And when we might start to expect to see some results coming from those 3? And the third was, you mentioned that, obviously, the gas trading business in NPR is fluctuations. And of course, we like fluctuations when they're positive and we don't like them when they are negative. Given that fluctuation being last year being so strong, can we take it that last year was probably more -- they are sort of the kind of top of the range, and this quarter starts to imply where we are would be at the bottom of the range, or is -- are fluctuations actually over a wider variance than that?

Torgrim Reitan

Thank you, Peter. I think you ended up with 3 questions. So again, on the Venezuela, NOK 0.6 billion, that's related to devaluation of the bolivar, so if you can take that. Svein, if you can address the wells to watch and then drilling times, and then I can touch upon gas trading afterwards.

Svein Skeie

Okay. On the better-than-new -- on the bolivar effect, the reason why we're taking that as part of the NOK-adjusted worth is that it's a currency effect, and that it's kind of similar to other currency effects on other items that we do not adjust for, so that is the reason.

Svein Skeie

Yes, on the exact results from different wells. That is, as we said, we have already spudded in Cachalote in Mozambique, so that is ongoing. Then in these days, we are also done spudding Hoop and then Nunatak, where we should expect the returns drop in summer on that one. Those are the 2 particular that I would like to highlight.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Do you agree -- how long are they expected to drill? When might we get results?

Svein Skeie

I'm not 100% sure of the exact number or days on the 2 different wells.

Torgrim Reitan

Okay. On the gas trading side, I think it's fair to say that 2012 was a strong year. I mean, this quarter is not a good quarter, and it is partly driven by the structures in the markets and all networks. And it is also linked to that Snøhvit has been down in the quarter, so there has not been diversion opportunities on that LNG business that we run. So you should expect the trading results to fluctuate, and I won't characterize one as the maximum and the other as a minimum. But generally, there will be fluctuations.

Morten Sven Johannessen

Next question on the telephone, please.

Operator

Our next question comes from Brendan Warn from Jefferies.

Brendan Warn - Jefferies & Company, Inc., Research Division

Its Brendan Warn from Jefferies. Just 2 questions, if I may. The first one, circling back to a question from Lydia, and specifically on Snøhvit. And I believe I understand how that's had a number of challenges, but what sort of program's in place to resolve these challenges going forward, and what sort of program and who's accountable for that? And then just secondly, I'm just tying in to Peter Hutton, who should be allowed to ask 50 questions today. Just in terms of the Barents Sea program that's now kicked off that we've been waiting for, just what sort of net risk perspective resource is going to be tested with that program, please?

Torgrim Reitan

Okay, Snøhvit first. So Snøhvit, we took Snøhvit down for maintenance and when we write it up, we experienced leakages in the coal box -- tool box. So that has been fixed and repaired, and it is now ramping up close to maximum capacity. So we are using quite a bit of efforts on that asset to make it work like a Swiss clock. I think it's fair to say that we have been through all parts of that asset. When that is said, it has had its issues since the startup. But -- and then going forward, I can't give any guarantees, but most of the plan has been looked into. When it comes to the Barents Sea program, so that is starting now with new network, and the team of wells around the Skrugard harvest, and then we will test out a new play, the Hoop area, they're further north, and before it comes back to the Hammerfest basin in the end. So the risk resources here is -- I can't comment on that. I think it's fair to say that the Hoop area, which they're opening a new play, that is higher risk. And potentially that's a play opener in the wells around the Skrugard area, then the probability for discovery is much higher. And we know we have much better view on how much is the potential there. So there's a different risk profile across that program currently.

Operator

Our next question comes from Alex Topouzoglou from Exane BNP Paribas.

Alex Topouzoglou - Exane BNP Paribas, Research Division

Last. I know that opposition leaders are calling for Norway to potentially sell their holding -- well, 16% of their holding in Statoil, as it would give you better development prospects. So do you actually feel, in any way, constrained by the strategic shareholder or pressure than to developing project in a more expensive way than you otherwise would have done as an independent?

Torgrim Reitan

Thank you, Alex. It's, first of all, I think it's fair to say that the Norwegian state has, since the IPO, and before that as well, been a very good and long-term owner that has sort of given Statoil the necessary freedom and opportunity to grow and make strategic decisions. When it comes to what politicians will or will not do, that's for them to answer on. Generally, all shareholders can make up their mind on what to do with their shareholdings.

Alex Topouzoglou - Exane BNP Paribas, Research Division

Okay. So there hasn't been a dialogue with you over this process or anything like that?

Torgrim Reitan

It's not natural for -- to have such discussion.

Morten Sven Johannessen

Thank you. That will have to conclude our Q&A session for today. Today's presentation and Q&A session can be replayed from our website in a few days, and transcripts will also be made available. Any further questions can be directed to the Investor Relations team. You'll find contact information on the web. Thank you, all, for participating. And have a good afternoon.

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